Carbon dioxide (CO2) constitutes the largest fraction of greenhouse gases (GHG), which are widely believed to be a major contributor to climate change. As such, significant research and development effort has been dedicated to reduce and/or eliminate emissions of CO2 into the atmosphere. Combustion of fossil fuels, especially coal, in electricity generating power plants is a significant source of CO2. To date, post-combustion CO2 removal from the stack gases via deployment of aqueous amine-based absorber-stripper technology is the only commercially available option, which is applicable to new units as well as to retrofitting the existing plants.
The stack gas of a modern gas turbine combined cycle (GTCC) power plant with advanced F, H or J class units contains about 4% CO2 by volume at near-atmospheric pressure (about 4.5% on a dry basis). Low flue gas pressure and density result in large volume flows requiring large piping, ducts and equipment, which are reflected in plant footprint and total installed cost. The only commercially available absorbents active enough for recovery of dilute CO2 at very low partial pressures are aqueous solutions of alkanolamines such as monoethanolamine (MEA), diethanolamine (DEA), methyl-diethanolamine (MDEA) and the newly developed sterically hindered amines (e.g., piperazine).
In a fossil fuel-fired power plant with post-combustion capture, a continuous scrubbing system is used to separate the CO2 from the flue gas stream by chemical absorption. The system consists of two main components:                an absorber in which the CO2 is removed, and        a regenerator (stripper) in which the CO2 is released in a concentrated form and the solvent is recovered.        
Prior to the CO2 removal, the flue gas (at around 90° C. at the heat recovery steam generator (HRSG) stack for the most efficient GTCC power plants) is typically cooled to about 50° C. and then treated to reduce particulates, that cause operational problems, and other impurities, which would otherwise cause costly loss of the solvent (e.g., in a direct contact cooler or “quench tower”). The amine solvent absorbs the CO2 (together with traces of NOx) by chemical reaction to form a loosely bound compound. A booster fan (blower) is needed to overcome the pressure loss in the capture plant and is a significant (parasitic) power consumer.
The largest power consumption by the amine system is due to the large amount of heat required to regenerate the solvent. The temperature level for regeneration is normally around 120° C. This heat is typically supplied by steam extracted from the bottoming cycle and reduces steam turbine power output and, consequently, net efficiency of the GTCC plant significantly.
As for all other carbon capture technologies, electrical power is consumed to compress the captured CO2 for transportation to the storage site and injection into the storage cavern.
Technologies for gas sweetening and syngas purification using alkanolamines have been extensively utilized in the chemical process industry (CPI) over the past century. Nevertheless, large-scale recovery of CO2 from flue gas poses several serious challenges. Most important of these (for a GTCC plant), e.g., low CO2 partial pressure and high regeneration energy, have already been mentioned. In addition, oxygen in the flue gas (about 12% by volume at the HRSG stack) can cause corrosion and solvent degradation (due to the absence of many impurities, which are amply present in coal-fired power plant flue gases, e.g., SOx (negligible), soot, fly ash and mercury, arguably the only significant degrading agent in GTCC flue gas is oxygen). While inhibitors have been reasonably effective in mitigating these effects, the need for continuous removal of unavoidable solution contaminants adds to operating costs.
Thus, in a natural gas-fired GTCC framework, post-combustion CO2 capture plant design challenges are as follows:                to minimize regeneration energy by selecting a solvent with a relatively low reaction energy;        to use the lowest possible exergy steam extraction to provide the requisite energy;        to cool the gas turbine exhaust gas to the lowest possible temperature in the HRSG;        to maximize the CO2 content of the HRSG stack gas; and        to minimize the O2 content of the HRSG stack gas.        